To assess the economic feasibility of a hydrocarbon reservoir, obtaining estimates of formation properties such as, but not limited to, permeability, pore pressure, and hydrocarbon type (among other properties) are essential. Permeability, porosity and pore pressure of a reservoir needs to be understood to be able to estimate the amount of fluids stored in the reservoir and the rate at which reservoir fluids can be produced. Such reservoir properties need to be measured, derived or otherwise estimated and the accuracy of such properties used during the economic viability study in connection with the commercial exploitation of a reservoir will greatly impact the final outcome. Therefore a reasonable certainty and accuracy of such properties are vital in the successful exploitation of an oil and/or gas well.
Furthermore said accuracy and understanding of such properties becomes more important as the permeability decreases. To put this into perspective, a typical sandstone reservoir might have a permeability measurement on the order of one Darcy wherein an accuracy of +/−10% might not drastically impact the final production of hydrocarbon from the reservoir. Alternatively, the permeability of what are referred to in the industry as hydrocarbon bearing shale reservoirs or tight gas reservoirs are typically on the order of one thousandth of a millidarcy (0.001 md) or lower, wherein a small percentile error may make the difference between a producing interval and a non-producing one.
The industry has perfected numerous ways to measure permeability and pore pressure of a subsurface layer over the years and a person of ordinary skill in the art will have access to multiple literature sources where these methods are explained. Such methods, although routinely and successfully used on a regular basis in medium to high permeability reservoirs, are not viable in reservoirs with low permeability due to the extended period of time needed to reach a stable measurement that is representative to the formation measured. The large majority of the methods used to measure permeability and pore pressure of a formation either inject or withdraw a known volume of fluid from the formation; by plotting the time it takes to reach a stable pressure, this can be measured until stable or extrapolated in time, the pore pressure and permeability to a known fluid can be measured with relatively high accuracy. The challenge in a low permeability formation is that reaching a stable pressure measurement after either injecting or withdrawing a volume of fluid by conventional means will take a large amount of time, rendering the test by conventional means impractical.
One of the conventional approaches to measuring permeability and pore pressure routinely used within the industry uses a wellbore formation tester probe or a dual packer tool, to isolate an interval from the mud column and then reduce the pressure of the isolated zone. This causes fluid to flow from the formation into the isolated volume, now with lower pressure than the reservoir, when the pressure in the isolated volume is equal or about the same as the reservoir pressure, the test stops. The pore pressure is determined from the pressure response during the pressure increase. However, in low permeability formations, such as shales, the fluid flow from the reservoir into the isolated volume is too slow to realistically draw the reservoir pressure down, shut in and allow it to build to a point that reservoir pressure can be estimated in a manageable and economical time frame.
An alternate method used in the industry to estimate pore pressure and permeability is using the injection and “fall-off” technique wherein an interval of the reservoir is isolated, this time using drill pipe or coiled tubing coupled with packers, and fluid is pumped from the surface to create a fracture in the formation. A pressure gauge is positioned either at the surface or downhole to monitor the pressure “fall-off” as fluid leaks off into the formation, either into the rock matrix or into fissures contained within the formation. After the newly created fracture is closed (an event a person skilled in the art will be able to determine by watching a pressure over time plot) the pressure continues to be monitored until a linear or radial flow regime can be identified. An extrapolation to infinite time can then be done to obtain the formation pore pressure. Using this technique of pumping fluid from the surface results in large volumes of fluid being injected into the formation before the pumps at surface can be stopped; taking this into account one can conclude the time needed to achieve a pressure falloff estimation of permeability or pore pressure in low permeability formations is quite long and will typically not be economical.
Another alternate method to overcome the problem of large volumes of fluid being pumped into the formation is to use nitrogen gas to create the fracture and record the pressure fall-off. This method reduces the fall-off time considerably but the times are still on the order of days or weeks to reach an adequately accurate estimation of pore pressure or permeability for low permeability formations such as shale or tight gas reservoirs. Other issues such as injected fluid compressibility errors are also introduced.